Many high-pressure/high-temperature (HP/HT) wells have been drilled and completed in the Gulf of Mexico and onshore Texas and Louisiana. However, the presence
of small amounts of hydrogen sulfide (H2S), typically in the parts per million (ppm) range, has caused considerable difficulty in completing such wells in compliance with NACE MR0175/ISO 15156. The primary and most recognizable limitation this standard imposes is the 0.05 psia H2S partial pressure threshold for sour service. For a well with 15,000 psig bottomhole pressure, for example, there need only be 3.5 ppm H2S for the standard to be invoked. The problem is that it is almost impossible to accurately measure this amount of H2S.
Because of the difficulty in accurately measuring H2S, some companies have argued that HP wells should be considered sour from the start. Other companies, however, have chosen to ignore the possible presence of H2S to avoid the complications created by complying with NACE MR0175/ISO 15156.
A typical example is a steel casing tieback string that ties the production liner back to the surface. This string is the first production casing outside of the tubing that can be exposed to H2S if there is a leak. Historically, this string has been designed to be compliant with NACE MR0175/ISO 15156.
In HP/HT wells, the production tieback is often casing with outside diameters (OD) that can be as large as 103?4 in., with wall thicknesses sometimes exceeding 1 in. This size is required to contend with the combined axial loads and collapse or burst loads. There also is a requirement for a subsurface safety valve in this location that has an OD larger than the tubing, so the tieback string must have a large enough inside diameter (ID) to accommodate the valve.
In designing HP/HT wells, API 5CT Grade Q125 casing can be required for strength. However, since Q125 steel has no resistance to sulfide stress cracking (SSC), a heavier wall C110 steel casing, which is currently a non-API sour service grade, can often handle the mechanical design. The problem is that NACE MR0175/ISO 15156 prohibits C110 steel from being run to surface, restricting its use to depths where the temperatures are ? 150?F (65?C). Using grade T95 steel is the only way to meet the standard for all temperatures all the way to the surface. This restriction in materials is extreme, and it creates serious technical issues.
For example, even if 85?8-in. OD 1-in. wall thickness C110 steel would suffice for the tieback casing, it could not be used because it cannot be run to surface. T95 steel would have to be used instead. The T95 steel would have to have a wall thickness of 1.187 in. to maintain the appropriate mechanical loads, which translates to a reduction
in ID. The decrease in ID generally causes dimensional issues and constraints (such as sufficient room for the subsurface safety valve) that cannot be easily overcome.
Increasing the wall thickness also leads to manufacturing limitations of the steel, and at some point the wall thickness required simply cannot be manufactured. This leaves the well designer and oil company with the choice of not completing the well or running several thousand feet of corrosion-resistant alloy that meets NACE/ISO 15156 strength and hardness criteria.
Some oil companies are choosing neither option, instead running C110 steel to surface. Less conscientious companies ignore these issues and run API 5CT Q125 casing that has no resistance to SSC. While it is recognized that NACE MR0175/ISO 15156 has a provision to tests alloys for specific well applications and use the results to justify the use of those alloys that are not compliant, the reality is that except in the case of a few major oil companies, this is rarely done. Instead, companies select alloys based on manufacturers’ test data and brochures.
If NACE MR0175/ISO 15156 is to be upheld as a standard, the industry must begin immediately to put it on a scientific footing instead of relying on old rules. Selection of the 0.05 psia limit was an empirical choice based on experience and has worked for many years. However, it is now recognized that at high pressures the partial pressure approach is not correct, and fugacity along with reduced solubility of H2S due to methane influences must be used to evaluate SSC potential. Until the industry carries out a formal scientific study that elucidates the correct means to address the potential for SSC based on H2S content, fugacity, and pressure, the inability of NACE MR0175/ISO 15156 to correctly predict the SSC of high strength components will result in the increasing irrelevance of the standard.
Recommended Reading
Petrie Partners: A Small Wonder
2024-02-01 - Petrie Partners may not be the biggest or flashiest investment bank on the block, but after over two decades, its executives have been around the block more than most.
Laredo Oil Subsidiary, Erehwon Enter Into Drilling Agreement with Texakoma
2024-03-14 - The agreement with Lustre Oil and Erehwon Oil & Gas would allow Texakoma to participate in the development of 7,375 net acres of mineral rights in Valley County, Montana.
Nebula Energy Buys Majority Stake in AG&P LNG
2024-01-31 - AG&P will now operate as an independent subsidiary of Nebula Energy with key offices in UAE, Singapore, India, Vietnam and Indonesia.
JMR Services, A-Plus P&A to Merge Companies
2024-03-05 - The combined organization will operate under JMR Services and aims to become the largest pure-play plug and abandonment company in the nation.
The OGInterview: Petrie Partners a Big Deal Among Investment Banks
2024-02-01 - In this OGInterview, Hart Energy's Chris Mathews sat down with Petrie Partners—perhaps not the biggest or flashiest investment bank around, but after over two decades, the firm has been around the block more than most.